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The North Cross Devonian Unit is located in the Crossett Field at the southern edge of the central basin platform in West Texas. The reservoir is a chalky, siliceous carbonate with 21% porosity, 3 md permeability and has an average pay thickness of 90 feet. There are 17 producers, 6 CO, injectors, 3 residue gas injectors, and 2 TA wells in the unit (Fig. 1). In 1964, residue casing head gas injection was started to" maintain reservoir pressure, and CO, injection was begun in 1972.

This paper is divided into two sections-the first covering a discussion of the types of prime movers
used in the oil fields, their cooling systems and ignition. The second part covers fuel systems, lubrication
and general maintenance items. Almost all types of prime movers have been used at one time or another in the oil fields. Some of these have proven satisfactory, but many others have been discarded in favor of more acceptable types of equipment.

Slow speed pumping engines may be defined as engines of speeds up to 500 or 600 rpm. These engines are generally single or twin cylinder design and may be either two or four cycle.

This paper is a review of the operation and performance of the Goldsmith-Cummins (San Andres) Unit, The Unit is located in northwest Ector County, Texas. It produces from the San Andres dolomite at approximately 4200 ft. The general Goldsmith Field structure is an anticline with two large domes connected by a productive saddle. Gas caps are present in portions of the field. First field production began in 1934." The Unit is operated by Atlantic Richfield Company. It is composed of 191 wells; most wells were drilled and completed prior to 1940.

Secondary Recovery was introduced to the oil field some years ago. One of the most advanced secondary recovery projects to date was "kicked off" by the Atlantic Refining Company on May 9, 1958, on the H.T. Boyd Lease in Slaughter Field, Texas. This project consists of injecting propane, then gas, then water into the San Andres pay. This paper will explain briefly the operation and problems encountered in this Miscible Slug Project.

Factors affecting the proper selection, installation and operation of deep shaft-driven centrifugal pumps. Use in source wells for secondary recovery projects is outlines, especially with reference to temperature and solids content of the supply water.

Hydraulic pumping units are classified as surface or sub-surface. Our discussion refers only to surface units which reciprocate a sucker rod string connected to a sub-surface plunger pump. Hydraulic unites may be classified as counterbalanced or non-counterbalanced. The counterbalance is provided by weights or compressed gas. Our discussion will be based on compressed gas- counterbalanced units and non-counterbalanced units.

The operation and maintenance of equipment on pumping wells has always been considered the function
of the field man in the oil business. Primarily this has been true because of the fact that the field man,
through his training and experience, has handled the equipment and learned the techniques and procedures
suitable for the pumping of individual wells under the varying conditions that are encountered. The operation, care, and maintenance of the surface equipment, particularly the pumping unit, is what we would like to discuss here.

The increasing cost of producing oil has caused operators to expend every effort to reduce operating expense. This expense is always increased when an artificial lift is required. The most popular type of artificial lift has been the beam pumping unit. The operation of this type of pumping unit may become very costly without proper care and maintenance of the equipment. Primarily, the responsibility for this operation falls on the field personnel of the oil company. Through training and experience, they have learned the techniques and procedures required for the pumping of individual wells.

Several operational changes have taken place at Block 31 to reduce operating costs and increase revenue. The most significant change has been the utilization of waste heat for treating oil emulsions. This has resulted in increased gas sales by reducing fuel gas requirements, a reduction in operating costs, and the elimination of a potential safety hazard. Computerized test equipment has been installed to provide more accurate testing, which in turn has provided improved data to assist in the management of the reservoir.

Federal regulation of prices charged by producers of crude oil was based on a "property" concept focusing on the "right to produce" as it existed in 1972, which the Department of Energy (DOE) and its predecessor, the Federal Energy Administration (FEA) attempted to define and clarify through numerous Rulings, Interpretations and Decisions.

Water soluble polymers find three major applications in oilfield enhanced oil recovery projects. Two of these applications involve reservoir fluid mobility control while the third involves profile control via reservoir heterogeneity modification. All polymer applications in the oilfield require certain operational practices to ensure that the polymers can function as designed. Many of the design criteria involved in polymer applications include production and injection equipment modifications in conjunction with reservoir fluid chemistry considerations.

This paper points out some of the operational difficulties that may arise in water flooding and shows major factors which must be considered to arrive at a solution to the problems.

This paper is presented to clarify a few of the general problems encountered in water flood operations. The production personnel are responsible for the production of the water supply wells, operation of a water plant and distribution system, and supervision of water injection wells. These duties are in addition to their usual occupation

The recent growth in applications of a new carbonate stimulation technique, which involves the construction of numerous tunnels or short laterals out of a main wellbore by using coiled tubing, has yielded excellent production improvements. A simplified mathematical model to analyze this acid stimulation process is presented in this paper. From the perspective of reservoir properties, this simulation takes into account the reservoir heterogeneity, drainage size, permeability, fluid characteristics, porosity and skin factor.

A case study has been conducted on Red Fork formation wells with bottomhole temperatures ranging from 225 degrees -250 degrees Fahrenheit. The fracturing applications and techniques in this area had historically provided lower than expected post-treatment productivity and a rapid decline rate, .suggesting that the fracture conductivity were less than optimum. Joint efforts of the operator and service company, utilizing state-of-the-art fluids, breakers, and design methodologies, were employed to optimize well productivity.

Many of the benefits of the Ultra-High-Slip motor can be realized by its installation under the exact same conditions as that of the Nema D motor. However, to maximize the system efficiency and minimize operating cost, some changes may be required to optimize the Ultra-High-Slip system. The amount of effort required to optimize your installation will depend upon the particular well. In this paper, we will be discussing three well tests. All of them were conducted in 1985, Andrews County, Texas, for two different operators and on three different wells.

A field demonstration of the application of the bottom hole pressure data, as received from Real Time Diagnostics" wireless pressure transmission system, improved the efficiency of PanCanadian Petroleum Limited's 8A-19-38-Ol-W4m well in the North Bodo field of northeast Alberta, Canada. An illustration of servicing a typical North Bodo slant well on a pad of wells is shown in Figure 1.

The objective of this project is to use data mining to analyze well completion data to determine if trends or interesting patterns exist between well completion and stimulation methods and subsequent production. While a multitude of completion and stimulation techniques exist there are few objective, systematic examinations of their relative utility. A 370 well subset of basin Dakota wells drilled during 1994-2004 was examined to determine the feasibility of this concept with 58 additional wells drilled during 2004-2006 used for testing.

This paper chronicles efforts to extend batch treatments using hydrocarbon-solvent solutions of corrosion inhibitor. Inhibitors were developed in the laboratory using parameters felt to be important for this endeavor. That is, good high inhibitor concentration inhibition, good reduced-inhibitor inhibition, and intermediate brine dispersibility. Field- testing proved these inhibitors to be effective during the extended intervals.

This paper describes a downhole separation technique that diverts the formation fluids into the basing annulus near the top of the downhole separator so that the liquids and gas can separate by gravity.

A method is presented for optimizing roller cone bit hydraulics programs to provide minimum cost per foot drilled. The method differs from traditional optimization techniques in that optimum pump operating conditions are determined rather than being arbitrarily imposed as a constraint on the optimization process. The method considers rate of penetration (ROP) response to increased bit hydraulic horsepower (BHHP) as well as increased fuel and pump maintenance costs to provide increased BHHP.

The Glorieta, Upper Paddock, and Lower Paddock formations were unitized in the Vacuum Field (S.E. New Mexico) by Texaco in 1992 creating the Vacuum Glorieta West Unit. A technical committee made up of working interest owners was formed to determine operational matters for the newly formed unit. The technical committee determined that the Upper and Lower Paddock intervals contained the more prolific productive capacity and provided the most suitable median for waterflooding. Consequently, unit wide water injection in those intervals commenced late that same year.

Tracing the fall of the plunger down the tubing can be used to optimize the operation of plunger lifted wells. On plunger lifted wells an acoustic liquid level instrument can be used to collect a series of liquid level shots down the tubing. These measurements are used to monitor the position of the plunger, as the plunger falls down the tubing during the time period the controller has closed the surface valves and the well is shut-in. The collected data is used to determine the 1) fall velocity of the plunger and 2) time for the plunger to fall to liquid.

Many factors are involved when selecting the most cost effective artificial lift system. This paper will discuss the advantages of The DynaPump Intelligent Long Stroke Hydraulic Pumping System compared to other artificial lift systems. This system has characteristics that allow for operation at much slower strokes per minute greatly reducing tubing and sucker rod wear while retaining the ability to produce at greater volumes from deeper depths than conventional beam pumping units.